Apparatus and method for abrasive jet perforating

ABSTRACT

There is provided a perforating tool comprising a housing, an inlet defined within the housing, a perforator fluid passage defined within the housing, and disposed in fluid communication with the inlet, and a nozzle, press-fit into the housing, and disposed in fluid communication with the perforator fluid passage.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 62/039,126, filed Aug. 19, 2014, the entire contents of which are incorporated by reference.

FIELD

The present disclosure relates to devices configured for jetting abrasive fluid for creating perforations within a wellbore, and thereby enabling fluid treatment of a subterranean formation, such as hydraulic fracturing, and methods using such devices.

BACKGROUND

In some hydraulic fracturing operations, the fracturing fluid enters the subterranean formation through one or more openings or bores. The openings may be formed using a variety of techniques including jetting, perforating using explosive charges, and using casing valves. Jetting requires that a fluid pass through a nozzle at high pressure, where the fluid is generally supplied through the use of pumps or other pressurization equipment at the surface of the wellbore.

SUMMARY

In one aspect, there is provided a perforating tool comprising a housing, an inlet defined within the housing, a perforator fluid passage defined within the housing, and disposed in fluid communication with the inlet, and a nozzle, press-fit into the housing, and disposed in fluid communication with the perforator fluid passage.

In another aspect, there is provided a perforating tool comprising a housing, an inlet defined within the housing, a perforator fluid passage defined within the housing and disposed in fluid communication with the inlet, a nozzle, extending through the housing to define a jetting orifice, and disposed in fluid communication with the perforator fluid passage, cladding, surrounds the jetting orifice, and a retainer, extending from the housing, and including a bevelled surface that retains the cladding in relative disposition to the nozzles such that the cladding surrounds the jetting orifice.

In a further aspect, there is provided a perforating tool comprising: a housing, an inlet defined within the housing, a perforator fluid passage defined within the housing and disposed in fluid communication with the inlet, a nozzle, extending through the housing to define a jetting orifice, and disposed in fluid communication with the perforator fluid passage, and cladding, surrounding the jetting orifice, wherein the jetting orifice is oriented such that, when the perforating tool is disposed downhole and operational for perforating a wellbore, a ray that is extending along the axis of the jetting orifice, in an uphole direction, is disposed at an acute angle of at least ten (10) degrees relative to an axis that is orthogonal to the axis of the perforator fluid passage.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a side sectional view of an embodiment of an apparatus of the present disclosure;

FIG. 2 is an elevation view taken from one end of a partially assembled apparatus of FIG. 1, during the assembly of the apparatus of FIG. 1, prior to press-fitting of the nozzle within a mandrel;

FIG. 3 is a side sectional elevation view, taken along lines C-C in FIG. 2, illustrating the partially assembled apparatus of FIG. 1;

FIG. 4 is an elevation view taken from one end of a partially assembled apparatus of FIG. 1, during the assembly of the apparatus of FIG. 1, and at a later stage of assembly than that illustrated in FIGS. 3 and 4, and after press-fitting of the nozzle within the mandrel;

FIG. 5 is a side sectional elevation view, taken along lines D-D in FIG. 4, illustrating the partially assembled apparatus of FIG. 1, and at a later stage of assembly than that illustrated in FIGS. 3 and 4;

FIG. 6 is a side sectional view of a bottom hole assembly incorporating the apparatus of FIG. 1, shown deployed within a casing; and

FIG. 7 is an unwrapped view of an embodiment of a J-slot profile that is integrated within the bottom hole assembly of FIG. 6.

DETAILED DESCRIPTION

As used herein, the terms “up”, “upward”, “upper”, or “uphole”, mean, relativistically, in closer proximity to the surface and further away from the bottom of the wellbore, when measured along the longitudinal axis of the wellbore. The terms “down”, “downward”, “lower”, or “downhole” mean, relativistically, further away from the surface and in closer proximity to the bottom of the wellbore, when measured along the longitudinal axis of the wellbore.

There is provided an abrasive perforating tool 10. The perforating tool 10 is shown as one of several components in a bottom hole assembly (“BHA”) 100. The BHA 100 is configured for disposition within a wellbore, and is positionable therein with a conveyance.

Suitable wellbores include vertical, deviated, horizontal or multi-lateral wells.

The wellbore may be a cased wellbore having a casing disposed therein. The casing is provided for, amongst other things, supporting the subterranean formation within which the wellbore is disposed. The casing includes a plurality of successive casing sections joined by a corresponding plurality of collars. The casing lines the wellbore and is, typically, cemented to the subterranean formation. This enables fluid treatment of an interval or zone of the subterranean formation, through the casing (as will be further explained below), while preventing, or substantially preventing, fluid communication between the treated zone and another zone of the subterranean formation that is remote from the one being treated. The resulting installation is referred to as a cemented completion.

The conveyance includes a conduit. In some embodiments, for example, the conveyance 300 is in the form of a suitable tubing string, such as jointed pipe, concentric tubing, or coiled tubing. As used herein, the term BHA 100 refers to the combination of tools supported on the end of the conveyance. The conveyance extends from an oilfield surface and is connected to suitable oilfield surface equipment.

The perforating tool 10 includes a housing (or “body”) 12. A perforator fluid passage 14 is defined within the housing 12 between an inlet 16 and an outlet 18. The inlet 16 is configured to receive a fluid from a supply source at the surface via the conduit. In some operational implementations, such as when the received fluid is supplied for effecting hydraulic fracturing, the outlet communicates at least a fraction of the received fluid in a downhole direction to other tools of the BHA 100.

The perforating tool 10 also includes one or more jetting nozzles 20 extending through the housing. The jetting nozzles 20 are operable to emit a high velocity and or high pressure stream of the received fluid, generally in the radially outward direction relative to the housing, for perforating the casing 202. In some embodiments, for example, the nozzles 20 include a nozzle fluid passage 21 having a maximum cross-sectional flow area of 0.0123 square inches to 0.05 square inches. In some embodiments, for example, the nozzle 20 defines an axial flow length of 0.5 inches to 1.0 inches.

In some operational implementations, for example, the received fluid is an abrasive slurry. In some embodiments, for example, the abrasive slurry is a mixture including water and sand. In some embodiments, for example, the abrasive slurry includes 0.3 pounds to 1.2 pounds of 100 to 12 mesh Ottawa sand, or 0.3 pounds to 1.2 pounds of manufactured proppants, per gallon of water or viscosified water.

In some embodiments, for example, the nozzle 20 is configured to conduct the abrasive slurry at a speed of at least 300 feet per second. In some embodiments, for example, the nozzle 20 is configured to conduct the abrasive slurry at a speed of 500 feet per second.

In some embodiments, for example, the material of the nozzle 20 has a hardness value of at least 90.5 on the Rockwell A scale. In some embodiments, for example, the hardness-value is 93 on the Rockwell A scale.

In some embodiments, for example, the material of the nozzle 20 has relatively low ductility (is relatively brittle) and can, therefore, be relatively difficult to work with, such that this characteristic is, in some respects, being compensated for by other design features. In this respect, in some embodiments, for example, the material of the nozzle is characterized by an elongation of less than 5%.

In some embodiments, for example, the material of the nozzle 20 includes a carbide, such as tungsten carbide or boron carbide. In some embodiments, the material of the nozzle 20 is a composition including at least 85 weight % of tungsten carbide, based on the total weight of the nozzle 20. In some embodiments, the material of the nozzle 20 is a composition including 85 weight % to 95 weight % of tungsten carbide, based on the total weight of the nozzle 20.

In some embodiments, for example, the material of the nozzle 20 is a ceramic material, such as alumina.

The nozzle 20 is press-fit within a corresponding throughbore (or hole) 1203 of the housing 12. By integrating the nozzle 20 within the housing 12 by press-fitting, the wall thickness of the housing 12 may be made thinner, thereby permitting provision of a fluid passage 14 having a relatively larger cross-sectional flow area. With a fluid passage 14 having a relatively larger cross-sectional flow area, in some embodiments, for example, the conducting of hydraulic fracturing fluid, through the BHA (such as in a “coiled tubing frac”), for hydraulic fracturing of the subterranean formation, is made easier. As well, in some embodiments, for example, the deployment of a ball through the fluid passage 14, for functioning as a check valve, and thereby interfering with downhole flow of abrasive slurry that may be supplied to the BHA for perforating of the casing 202 by jetting through the nozzles 20, is facilitated by the relatively larger cross-sectional flow area of the fluid passage 14.

In some embodiments, for example, the nozzle 20 is a one-piece nozzle.

In some embodiments, for example, the perforating tool 10 includes cladding 22, and the cladding 22 surrounds jetting orifices 24 defined within the nozzles 20. The jetting orifices 24 are configured to eject the fluid being delivered through the nozzles 20. The cladding functions 22 to protect the jetting orifices 24 (and nozzles 20), and those portions of the housing 12 surrounding the nozzles 20, from damage due to splashback or rebound of the abrasive slurry that is ejected by the nozzles 20. In some embodiments, for example, the cladding 22 presents an outermost surface configured to receive splashback while abrasive slurry is being ejected by the nozzles 20 against casing 202 within a wellbore during perforating.

In some embodiments, for example, the material of the cladding 22 has a hardness value of at least 90 on the Rockwell A scale. In some embodiments, for example, the hardness value is 92 on the Rockwell A scale.

In some embodiments, for example, the material of the cladding 22 has relatively low ductility (is relatively brittle) and can, therefore, be relatively difficult to work with, such that this characteristic is, in some respects, compensated for by other design features. In this respect, in some embodiments, for example, the material of the cladding 22 is characterized by an elongation of less than 5%.

In some embodiments, for example, the material of the cladding 22 includes a carbide, such as tungsten carbide or boron carbide. In some embodiments, the material of the cladding 22 is a composition including at least 85 weight % of tungsten carbide, based on the total weight of the cladding 22. In some embodiments, the material of the cladding 22 is a composition including 85 weight % to 95 weight % of tungsten carbide, based on the total weight of the cladding 22.

In some embodiments, for example, the material of the cladding 22 is a ceramic material, such as alumina.

In some embodiments, for example, the cladding 22 is in the form of a plate. In some embodiments, for example, the cladding is in the form of a sleeve that extends about the perimeter of the housing. In some embodiments, for example the cladding 22 includes apertures or holes 2201 that are disposed in alignment with the jetting orifices 24.

In some embodiments, for example, the perforating tool 10 further includes a retainer 26 that extends from the housing 12 and functions to retain the cladding 22 against the housing 12. In some embodiments, for example, the retainer 26 includes a bevelled surface 28 that retains the cladding 22 in relative disposition to the nozzles 20 such that the cladding 22 surrounds the nozzles 20 (and protects the nozzles from splashback, as above-described). In this respect, in some embodiments, for example, the cladding 22 includes a bevelled surface 30, corresponding to, and disposed in opposition to, the bevelled surface 30 of the retainer 26. In some embodiments, the retainer 26 is in the form of a sleeve lock ring that is threaded to the housing 12.

In some embodiments, for example, the retention of the cladding 22 by the bevelled surface 28 of the retainer 26 is at least by way of interference.

The retention of the cladding 22 is made more robust by the bevelled surface 28. In the event that the cladding 22 fractures, the cladding 22 may still be retained by the bevelled surface 22.

In some embodiments, for example, the housing 12 is a generally cylindrical-shaped tube, with the inlet 16 and the outlet 18 disposed at opposite ends of the tube and joined by the perforator fluid passage 14. The nozzles 20 extend from the perforator passage 14 and through a sidewall of the housing 12.

The following is a description of an embodiment of a method of assembling of an embodiment of the tool.

Referring to FIGS. 2 and 3, the nozzle 20 is pressed onto and over a “press in” plug 402. After the nozzle 20 has become disposed over the press in plug 402, a guide pin 404 is threaded onto the press in plug 402 such that the guide pin 404 is disposed over the nozzle 20, and such that the nozzle 20 is retained between the guide pin 404 and a shoulder 406 of the press in plug 402. The resultant assembly defines the nozzle subassembly 400. The cladding 22, in the form a sleeve 22, is slid over a mandrel 500, and the cladding holes 2201 are aligned with mandrel holes 501 defined by throughbores 503, provided within the mandrel 500 and corresponding to the housing throughbores 1203. The retainer (sleeve lock ring) 26 is then threaded onto the mandrel 500 to retain the cladding 22. The nozzle subassembly 400 is then installed through one of the throughbores 503. The nozzle 20 is slightly oversized relative to the throughbore 503. A wedge tool 600 is then positioned within the mandrel 500 for pressing against the nozzle subassembly 400. A snapshot of the assembly process, at this stage, is illustrated in FIGS. 2 and 3.

The nozzle subassembly is pressed into the throughbore 503 by a force translated by the wedge tool 600 (in the embodiment illustrated, the force is applied in a direction towards the left). A snapshot of the assembly process, at this stage, is illustrated in FIGS. 4 and 5.

The wedge tool 600 is then retracted, the guide pin 404 is removed from the press in plug 402, and the press in plug 402 is removed from the press fit nozzle 20. The nozzle 20 is subsequently machined by electrical discharge machining such that the nozzle 20 is flush with the cladding 22.

Referring to FIG. 6, in some embodiments, for example, the perforating tool 10 is incorporated within the BHA 100. In this respect, in some embodiments, for example, the perforating tool 10 is threadably connected to one or more other tools of the BHA 100.

Referring to FIGS. 1 and 6, in some embodiments, for example, the nozzle 20 when integrated within the housing 12 of the tool 10, is oriented such that, when the tool 10 is integrated within the BHA 100, and the BHA 100 is disposed within a wellbore, and while fluid (such as an abrasive slurry) is being conducted through the tool 10, the abrasive slurry is being ejected through the nozzle 20 and directed in an uphole direction for effecting perforation of casing that is lining the wellbore, with effect that a portion of a casing, disposed uphole relative to the tool 10, is perforated. In some embodiments, for example, the orientation is such that a ray 241 that is extending along the axis 243 of the jetting orifice 24 is disposed, in an uphole direction, at an acute angle of at least 10 degrees relative to an axis that is orthogonal to the axis 141 of the perforator fluid passage 14. In some of these embodiments, for example, the orientation is such that the ray 241 that is extending along the axis 243 of the jetting orifice 24 is disposed, in an uphole direction, at an acute angle of 20 degrees relative to the axis that is orthogonal to the axis 141 of the perforator fluid passage 14. By virtue of this orientation, perforations are created uphole, relative to the tool 10. As a result, when hydraulic fracturing fluid is supplied through the annulus between the tool 10 and the wellbore, the entirety of the hydraulic fracturing fluid being supplied is not conducted past the tool 10, and at least (and, some examples, most) of the hydraulic fracturing fluid is conducted through the perforation(s) that have been created in the casing, uphole relative to tool 10. As such erosion of the tool 10, by the hydraulic fracturing fluid being supplied, is mitigated.

As discussed above, the BHA 100 is deployable within a wellbore. While the BHA is deployed within the wellbore, a wellbore annulus is defined between the BHA and the casing 202.

In some embodiments, for example, the BHA 100 includes a fluid conducting structure 102, a casing annulus sealing member 104, an equalization valve 106, a lower mandrel 108, and the perforating tool 10.

The fluid conducting structure 102 includes a fluid passage 1021. The fluid passage 1021 may be provided for effecting flow of fluid material for enabling, for example, perforation of the casing 202. The BHA 100 is configured such that, for some implementations, while the BHA 100 is disposed within the wellbore, the fluid passage 1021 extends downhole from the wellhead.

The fluid conducting structure 102 includes ports 107. While the BHA 100 is deployed within the wellbore, each one of the ports 107 extends between a wellbore annulus 204 and the fluid passage 1021. In this respect, in some implementations (see below), fluid communication is effected between the wellbore annulus 204 and the fluid passage 1021 through the ports 107.

The casing annulus sealing member 104 is provided and configured for becoming disposed in sealing engagement with the casing. The casing annulus sealing member 104 is mounted to the lower mandrel 108. The casing annulus sealing member 104 is configured to be actuated into sealing engagement with the casing, while the BHA 100 is deployed within the wellbore and has been located within a predetermined position at which fluid treatment is desired to be a delivered to the formation. In this respect, the casing annulus sealing member 104 is disposable between at least an unactuated condition and a sealing engagement condition. In the unactuated condition, the casing annulus sealing member 104 is spaced apart (or in a retracted state) relative to the casing. In the sealing engagement condition, the casing annulus sealing member 104 is disposed in the above-described sealing engagement with the casing, while the BHA 100 is deployed within the wellbore and has been located within a predetermined position at which fluid treatment is desired to be a delivered to the formation. The sealing engagement is with effect that fluid communication, through the wellbore annulus, and across the sealing member 104, between a treatment material interval and a downhole casing passage portion disposed downhole of the sealing member 104, is sealed or substantially sealed.

In some embodiments, for example, the casing annulus sealing member 104 is defined by a resettable sealing member 105A of a packer 105. The packer 105 is disposable between unset and set conditions. In the unset condition, while the BHA 100 is disposed within the wellbore, in some implementations (such as while the BHA 100 is located within a predetermined position at which fluid treatment is desired to be delivered to the formation) the sealing member 105A is spaced apart (in the retracted state) relative to the casing, nd thus, in effect, renders the sealing member 104 in the unactuated condition. In the set condition, the sealing member 105A is disposed in sealing engagement with the casing, while the BHA 100 is deployed within the wellbore and has been located within a predetermined position at which fluid treatment is desired to be a delivered to the formation, and thus, in effect, renders the sealing member 105A in the sealing engagement condition. Mechanically actuated locking devices or slips 105B may be positioned below the sealing member 105A to resist movement of the sealing member 105A down the wellbore when the sealing member 105A is in the set position. The setting and unsetting of the packer 105 is further explained below.

An equalization valve 106 is provided for at least interfering with fluid communication, through the fluid passage 1021, via ports 107 extending through the fluid conducting structure 202, between: (i) an uphole wellbore annulus portion that is disposed uphole relative to the casing annulus sealing member 104, and (ii) a downhole casing passage portion that is disposed downhole relative to the casing annulus sealing member 104, while the casing annulus sealing member 104 is sealingly engaging the casing. The uphole wellbore annulus portion is a portion of the wellbore annulus that is disposed uphole of the sealing member 104. In this respect, while the casing annulus sealing member 104 is sealingly engaging the casing, the equalization valve 106 is disposable between at least:

-   (a) a downhole isolation condition, wherein fluid communication,     through the fluid passage 1021, via the ports 107, between the     uphole wellbore annulus portion and the downhole casing passage     portion, is sealed or substantially sealed, and -   (b) a depressurization condition, wherein the uphole wellbore     annulus portion is disposed in fluid communication, through the     fluid passage 1021, via the ports 107, with the downhole casing     passage portion.

The equalization valve 106 includes a valve plug 110 and a valve seat 112. The valve plug 110 is connected to the conveyance 300 via a pull tube 214. In this respect, the valve plug 106 is moveable, in response to forces translated by the pull tube 114, that are being applied to the conveyance 300, between a downhole isolation position, corresponding to disposition of the equalization valve 106 in the downhole isolation condition, and a depressurization position, corresponding to disposition of the equalization valve 106 in the depressurization condition. The valve seat 112 is connected to the lower mandrel 108 (see below).

The valve plug 110 is configured for sealingly engaging the valve seat 112. While the valve plug 110 is disposed in the downhole isolation condition, the valve plug 110 is disposed in sealing engagement with the valve seat 112. While the valve plug 110 is disposed in the depressurization condition, the valve plug 110 is spaced apart from the valve seat 112.

Movement of the valve plug 110 from the downhole isolation position to the depressurization position is in a direction that is uphole relative to the valve seat 112. Such movement is effected by application of a tensile force to the conveyance 300, resulting in translation of such force to the valve plug 110 by the pull tube 114. Uphole movement of the valve plug 110, relative to the valve seat 112, is limited by a detent surface (or “stop”) 111 that is integral with the structure that forms the valve seat 112 (and is part of the equalization valve 106). In this respect, the valve plug 110 includes a shoulder surface, and the limiting of the uphole movement of the valve plug 110, relative to the valve seat 112, is effected upon contact engagement between the shoulder surface and the stop 111.

A check valve 122 is provided within the fluid passage 1021, uphole of the valve seat 112. The check valve 122 seals fluid communication between an uphole portion 1021A of the fluid passage 1021 and the uphole wellbore annulus portion (via the ports 107) by sealingly engaging a valve seat 1221, and is configured to become unseated, to thereby effect fluid communication between the uphole wellbore annulus portion and the uphole portion 1021A, in response to fluid pressure in the uphole wellbore annulus portion exceeding fluid pressure within the uphole portion 1021A by a minimum predetermined amount. In this respect, the check valve 122 permits material to be conducted through the fluid passage 1021 in an uphole direction, but not in a downhole direction.

In some implementations, for example, the material being supplied downhole through the wellbore annulus includes fluid for effecting reverse circulation (in which case, the equalization valve 106 is also closed), for purposes of removing debris from the wellbore annulus, such as after a “screen out”.

In some embodiments, for example, the check valve 222 is in the form of a ball that is retained within a fluid passage portion of the fluid passage 2021, uphole relative to the valve seat 221, by a retainer 2221.

After the casing has been perforated to form perforations within the casing, while the casing annulus sealing member 104 is disposed in the sealing engagement condition, and while the valve plug 110 is disposed in the downhole isolation position, treatment material may be supplied downhole and directed to the perforations, and through the perforations and into the treatment interval within the subterranean formation, through the uphole wellbore annulus portion. Without the valve plug 110 effecting the sealing of fluid communication, through the fluid passage 1021, between the uphole wellbore annulus portion and the downhole casing passage portion, at least some of the supplied treatment material may bypass the perforations and be conducted further downhole from the perforation via ports 107 to the downhole casing passage portion. Also, the check valve 122 prevents, or substantially prevents, fluid communication of treatment material, being supplied downhole through the uphole wellbore annulus portion, with the uphole fluid passage portion 1021A, thereby also mitigating losses of treatment material uphole via the fluid passage 1021.

The lower mandrel 108 is connected to the valve seat 112, and is thereby configured for receiving forces translated by the valve plug 110 (such as, for example, tensile or compressive forces applied to the conveyance 300) to the valve seat 112. The lower mandrel 108 is configured to receive compressive forces translated to the valve seat 112 by the valve plug 110 (and as applied to the conveyance 300) when the valve plug 110 has reached the downhole limit of its extent of travel relative to the valve seat 112 (i.e. the valve plug 110 is sealingly engaging the valve seat 112). The lower mandrel 108 is also configured to receive tensile forces in response to pulling up on the conveyance 300, which is translated to the valve seat 112 by virtue of the contact engagement between the shoulder surface of the valve plug 110 and the detent surface 111 that is connected to the valve seat 112.

A J-slot 82 is formed within the lower mandrel, for enabling the setting and unsetting of the packer 205, in response to forces applied to the conveyance 300, which are translated to the lower mandrel 208, as above-described. An unwrapped view of an exemplary J-slot is shown in FIG. 5 having three pin stop positions 821 a, 821 b, and 821 c, that are repeated about the lower mandrel. The three pin stop positions correspond to various conditions of the packer assembly, namely, the set position 821 a (in which the sealing member 205A is disposed in sealing engagement with the casing (and, specifically, the valve closure member 16) and the equalization valve 106 is disposed in the downhole isolation condition), the release (or “pull”) position 821 b (in which the sealing member 105A is spaced apart from the casing), and the running-in position 821 c (in which the valve plug of the equalization valve 106 is unseated, and the packer 105 is not set). A cam actuator or pin 105C, coupled to mechanical slips 105B, is disposed for travel within the J-slot. Debris relief apertures 823 may be provided at various positions within the J-slot 82 to permit discharge of settled solids as the pin slides within the J-slot 82.

In some embodiments, for example, the packer 105 is set by applying compressive forces to the conveyance 300. When the valve plug 110 is seated against the valve seat 112, these forces are translated to the lower mandrel 108. This results in engagement between an upper end of a setting cone 105D, mounted to the lower mandrel 108, and the sealing member 105A, which forces the sealing member 105A outwardly, compressing the sealing member 105A into sealing engagement with the casing. In parallel, a lower end of the setting cone 105D engages the mechanical slips 105B and the J-slot slides relative to the pin 105C. Due to frictional resistance provided by the locator 118, the setting cone 105D forces the mechanical slips 105B outwardly against the casing, and the movement of the J-slot relative to the pin 105C results in the pin 105C becoming disposed in the set position 821 a. The mechanical slips 105B are now gripping (or “biting into”) the casing 11, and the pin is resisting retraction of the mechanical slips 105B from the casing.

In some embodiments, for example, the lower mandrel 108 further includes a bullnose centralizer 1141 for centralizing the BHA 100.

In some embodiments, for example, the BHA 100 includes a lower subassembly 116. The lower subassembly 116 is slidably mounted to the lower mandrel 108, between the packer 105 and the bullnose centralizer 1141 The lower subassembly 116 includes a locator 118 for effecting desired positioning of the tool assembly relative to the casing. The locator 118 extends outwardly, relative to the lower mandrel 108, and is configured to engage the casing while the BHA 100 is being moved uphole or downhole. In some embodiments, for example, the locator 118 includes a locator collet 118A for engaging a corresponding recess within the casing and thereby resist movement of the BHA 100 relative to the casing.

The perforating tool 10 is disposed in fluid communication with the fluid passage 1021 for receiving abrasive slurry, from the surface, via the fluid passage 1021, and jetting the received abrasive slurry, via the nozzles 20, against the casing 202, for effecting perforating of the casing 202 in the vicinity of the nozzles 20.

The following describes an exemplary deployment of the BHA 100 within a cased wellbore, and subsequent supply of treatment material to a zone of the subterranean formation 100.

The BHA 300 is run downhole through the cased wellbore, past a predetermined position. Once past the desired location, a tensile force is applied to the workstring, and the predetermined position, at which the selected treatment material port is located, is located with the locator 118. The conveyance 300 becomes properly located when the locator becomes disposed within a locating recess within the casing 202. In this respect, the locator 218 and the locating recess are co-operatively profiled such that the locator 118 is configured for disposition within and engagement to the locating recess when the locator 218 is moving past the first locating recess. Successful locating of the locator 118 within the locating recess 111 is confirmed when resistance is sensed in response to upward pulling on the conveyance 300.

Once disposed in the pre-determined position, an abrasive slurry is then supplied through the fluid passage 1021. The supplied abrasive slurry is jetted through the nozzles 20 and against the casing 202, causing creation of perforations within the casing 202 so as to enable subsequent supplying of treatment material to the subterranean formation.

After the perforations are created, the conveyance 300 is forced downwardly, and the applied force is translated such that sealing engagement of the valve plug 110 with the valve seat 112 is effected. Further compression of the conveyance 300 results in setting of the packer 205 (as the lower mandrel 108 receives the compressive forces imparted by the conveyance 300), including its associated mechanical slips 105B, for effecting sealing engagement of the resilient sealing member 105A to the casing 202, and also for effecting the engagement (e.g. gripping) of the packer 105 to the casing 202.

Treatment material may then be supplied via the wellbore annulus 208, defined between the bottom hole assembly 100 and the casing 202, and through the created perforations and into the subterranean formation, thereby effecting treatment of the subterranean formation that is local to the perforations. The packer 105, in combination with the sealing engagement of the valve plug 110 with the valve seat 112, prevents, or substantially prevents, the supplied treatment material from being conducted downhole, with effect that all, or substantially all, of the supplied treatment material, being conducted via the wellbore annulus 208, is directed to the formation through the perforations.

In the above description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the present disclosure. However, it will be apparent to one skilled in the art that these specific details are not required in order to practice the present disclosure. Although certain dimensions and materials are described for implementing the disclosed example embodiments, other suitable dimensions and/or materials may be used within the scope of this disclosure. All such modifications and variations, including all suitable current and future changes in technology, are believed to be within the sphere and scope of the present disclosure. All references mentioned are hereby incorporated by reference in their entirety. 

1. A perforating tool comprising: a housing; an inlet defined within the housing; a perforator fluid passage defined within the housing, and disposed in fluid communication with the inlet; and a nozzle, press-fit into the housing, and disposed in fluid communication with the perforator fluid passage.
 2. The perforating tool as claimed in claim 1; wherein the material of the nozzle has a hardness value of at least 90.5 on the Rockwell A scale and is characterized by an elongation of less than 5%.
 3. The perforating tool as claimed in claim 1; wherein the material of the nozzle includes carbide material
 4. The perforating tool as claimed in claim 2; wherein the material includes at least 85 weight % tungsten carbide, based on the total weight of the nozzle.
 5. The perforating tool as claimed in claim 1, further comprising: a throughbore extending through the housing; wherein the nozzle is disposed within the throughbore. 6-12. (canceled)
 13. The perforating tool as claimed in claim 2, further comprising: a throughbore extending through the housing; wherein the nozzle is disposed within the throughbore.
 14. The perforating tool as claimed in claim 3, further comprising: a throughbore extending through the housing; wherein the nozzle is disposed within the throughbore.
 15. The perforating tool as claimed in claim 4, further comprising: a throughbore extending through the housing; wherein the nozzle is disposed within the throughbore.
 16. A perforating tool comprising: a housing; an inlet defined within the housing; a perforator fluid passage defined within the housing and disposed in fluid communication with the inlet; a nozzle, extending through the housing to define a jetting orifice, and disposed in fluid communication with the perforator fluid passage; cladding, surrounds the jetting orifice; and a retainer, extending from the housing, and including a bevelled surface that retains the cladding in relative disposition to the nozzles such that the cladding surrounds the jetting orifice.
 17. The perforating tool as claimed in claim 16; wherein the cladding includes a bevelled surface, corresponding to, and disposed in opposition to, the bevelled surface of the retainer.
 18. The perforating tool as claimed in claim 17; wherein the retention of the cladding by the bevelled surface of the retainer is at least by way of interference.
 19. The perforating tool as claimed in claim 16; wherein the material of at least the outermost surface of the cladding includes carbide material.
 20. The perforating tool as claimed in claims 17; wherein the material of at least the outermost surface of the cladding includes carbide material.
 21. The perforating tool as claimed in claim 18; wherein the material of at least the outermost surface of the cladding includes carbide material.
 22. The perforating tool as claimed in claim 19; wherein the material includes at least 85 weight % tungsten carbide, based on the total weight of the nozzle.
 23. The perforating tool as claimed in claim 20; wherein the material includes at least 85 weight % tungsten carbide, based on the total weight of the nozzle.
 24. The perforating tool as claimed in claim 21; wherein the material includes at least 85 weight % tungsten carbide, based on the total weight of the nozzle.
 25. The perforating tool as claimed in claim 16; wherein the material of at least the outermost surface of the cladding has a hardness value of at least 90 on the Rockwell A scale, and has an elongation of less than 5%.
 26. The perforating tool as claimed in claim 17; wherein the material of at least the outermost surface of the cladding has a hardness value of at least 90 on the Rockwell A scale, and has an elongation of less than 5%.
 27. The perforating tool as claimed in claim 18; wherein the material of at least the outermost surface of the cladding has a hardness value of at least 90 on the Rockwell A scale, and has an elongation of less than 5%.
 28. A perforating tool comprising: a housing; an inlet defined within the housing; a perforator fluid passage defined within the housing and disposed in fluid communication with the inlet; a nozzle, extending through the housing to define a jetting orifice, and disposed in fluid communication with the perforator fluid passage; and cladding, surrounding the jetting orifice; wherein the jetting orifice is oriented such that, when the perforating tool is disposed downhole and operational for perforating a wellbore, a ray that is extending along the axis of the jetting orifice, in an uphole direction, is disposed at an acute angle of at least ten (10) degrees relative to an axis that is orthogonal to the axis of the perforator fluid passage. 